Fortnightly - EAIhttp://www.fortnightly.com/tags/eai
enBundled against Changehttp://www.fortnightly.com/fortnightly/2014/01/bundled-against-change
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Mississippi draws a line in the sand.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Bruce W. Radford</p>
</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Bruce W. Radford</b> is publisher of <i>Public Utilities Fortnightly</i>. Contact him at <a href="mailto:radford@pur.com">radford@pur.com</a>.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - January 2014</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>On December 13, the day ITC gave up on buying Entergy’s multi-state transmission network (three days after Mississippi regulators had scuttled the deal) <i>Fortnightly</i> spoke with Linda Blair, ITC’s executive v.p. and chief business officer:</p>
<p>“This was in no way a transaction we needed to do,” said Blair.</p>
<p>“Our pipeline is still pretty full.”</p>
<p>As evidence, Blair cited the Thumb Loop line in Michigan, now nearing completion, and also its “V” Plan in Kansas, as examples of ITC key grid projects still moving ahead.</p>
<p>“That’s a testament to our model,” she noted, “to our singular focus on transmission.”</p>
<p>And Blair is probably right; ITC likely can prosper without Entergy’s lines. But can we say the same for the power industry as a whole, and for the Federal Energy Regulatory Commission? Because with this deal’s rejection, FERC comes out the big loser.</p>
<p>FERC has long promoted the Transco concept – one company owning nothing but transmission – as a useful adjunct to its vision of market-based pricing. And Justice Department’s Antitrust Division had said back in 2012 that if Entergy would spin off its lines to form a Transco, it would refrain from taking action to address allegations that Entergy had used its monopoly control to foreclose rivals from obtaining long-term firm transmission service. But the December 10 ruling by the Mississippi Public Service Commission consigns any would-be Entergy Transco to the trash heap.</p>
<p>The Mississippi opinion features a 20-page retrospective on the history of the Transco model – how various state commissions have dealt with Transco proposals over the years (GridFlorida, etc.) – that concludes with Mississippi PSC clearly rejecting FERC’s thesis that discrimination in transmission service provided by a vertically integrated utility justifies consideration of the Transco model:</p>
<p>“[A] ‘perception of bias’ is not proof of bias …,” as the PSC states.</p>
<p>“ITC’s independence is touted as a virtue, but approval of the transaction would leave ITC independent of [the PSC] and the local concerns of Mississippi ratepayers, the economy and the State.”</p>
<p>On first glance, perhaps, the PSC ruling appears to draw on public interest principles – calling the deal bad for ratepayers after crunching the numbers – to justify the decision to flatly reject any transfer of T lines from local utility Entergy Mississippi Inc. (EMI), to ITC Holdings, the out-of-state grid conglomerate. Despite claims by ITC that its single focus on transmission would yield benefits, the state commission remained unconvinced: “the benefit to Mississippi ratepayers,” it wrote, “is dubious.”</p>
<p>The PSC explains, rightly, that if the local utility sells off its transmission lines used to serve native load – unbundles them from retail distribution – then ratemaking authority passes to FERC. That means a higher revenue requirement, forged from generous federal grid incentives and a higher, federally authorized return on equity. The Mississippi commission finds that a selloff of grid assets to ITC could cost Entergy ratepayers at least $348 million over 30 years.</p>
<p>“We must view the proposed transaction for what it is,” the PSC declared: “an attempt by Entergy and its shareholders to monetize its transmission assets and extract the excess value.” <i>(See, Energy Mississippi, Inc., Miss. PSC No. EC123-0082-00, Joint Application for the Transfer of ownership and Control of entergy Mississippi Inc.’s Transmission Facilities, Final Order, Dec. 10, 2013.)</i></p>
<p>But as a law school professor might lecture his first-year class of budding lawyers, all this is just <i>dicta – </i>rich-sounding words added for effect that don’t really control the result of the decision. By contrast, in the strictest legal analysis, the Mississippi decision, if we read it by its own terms, doesn’t actually turn on a dollar-and-cents weighing of costs and benefits.</p>
<p>For if that were true, the case might well have swung the other way. And in fact ITC had anticipated the problem – that the deal appeared overly generous to ITC and Entergy stockholders – and so had offered a sweetener to even things up.</p>
<p>As ITC’s Blair told <i>Fortnightly,</i> “we and Entergy had put forth a rate mitigation plan to hold state ratepayers harmless until such time [in ‘perpetuity,’ if need be] as we could demonstrate benefits stemming from our Transco model.</p>
<p>“But the PSC did not give due consideration to our offer.”</p>
<p>Rather, the PSC’s decision draws a line in the sand, regardless of numbers. It declares premptive war on any attempt to divert ownership of local utility T lines to out-of-state control. It stands as wholesale repudiation of FERC policy: a defense to the death, if you will, of the traditional utility model of generation, transmission, and distribution, all under one roof.</p>
<p>Mississippi’s commissioners could just as easily have climbed up the courthouse steps and declared, “vertical integration today, vertical integration tomorrow, vertical integration forever.”</p>
<p>Let’s read the fine print. On pages 21 and 22 of the 90-page opinion, the PSC explains that “prior to a public interest finding” – <i>i.e.,</i> before you ever get to the cost-benefit analysis – you must first satisfy a “statutory prerequisite” laid down by the state legislature back in 2003 that, according to the state commission, mandates vertical integration for Mississippi’s electric industry: now and forever.</p>
<p>That legislation <i>(Miss. Code Annotated, sec. 77.3-23)</i> states that if a merger or sales transaction involves transmission facilities included in a utility’s rate base, the state commission must first find – before crunching numbers – that after the deal’s close, all native load customers will “be served on the same basis as before the transaction.”</p>
<p>The state legislature has never truly defined what that means. But with its December 10 ruling, the state commission now has. According to the PSC, “served on the same basis” means that transmission service must be provided after the deal according to “an equivalent foundation or framework” as had existed beforehand: which in this case means through grid assets owned by the retail utility and bundled with retail energy distribution service.</p>
<p>Thus the PSC ruling declares, in so many words, that no sale or merger deal involving transmission can pass muster in Mississippi, nor ought to, if at the end of the day, the retail utility will no longer remain vertically integrated, with transmission owned under the same roof as generation and distribution.</p>
<p>But here we should be clear: the Mississippi commission still wants to go forward with Entergy’s integration into MISO, the Midcontinent ISO.</p>
<p>The key lies with MISO’s special “bundled load” exemption, which in this case will preserve state PSC authority to set the transmission revenue requirement, provided that grid assets remained under ownership of the load-serving utility. </p>
<p>With Entergy joining MISO, the PSC notes, the cost of energy for the typical EMI ratepayer likely will fall, but with the state commission still retaining rate-setting authority over bundled transmission. And so the Mississippi commission finds no cause to oppose EMI’s integration into MISO.</p>
<p>That move, set for the middle of last month, appeared still on target at press time. Yet hearts were set aflutter in October, when the Missouri PSC said it would block integration into MISO of transmission assets held by Entergy Arkansas Inc. (EAI), but located in Missouri’s “Boot Heel” district, unless EAI somehow could bring the Midcontinent ISO to the negotiating table with Southwest Power Pool to hammer out a revised joint operating agreement to address loop flow issues arising from Entergy’s join-up with MISO – a feat clearly beyond EAI’s capacity to deliver, and something that even FERC had said it wouldn’t require.</p>
<p>The Missouri commission “withdrew” that order six weeks later, clearing the way for EIA to join MISO, and closing the case effective December 10. <i>(See, Mo.P.S.C. File No. EO-2013-043, Report and Order issued Nov. 26, 2013.)</i></p>
<p>But as the PSC noted, Entergy’s transfer of functional grid control to MISO would have been found not in the public interest had the commission looked only at effects on those Missouri ratepayers who wouldn’t be joining the RTO.</p>
<p>• • •</p>
<p>Here’s food for thought: Is one negawatt as good as another? Are negawatts fungible, like kilowatt-hours?</p>
<p>Late last year, in a case involving the New York ISO and brought by EnerNOC, Viridity, Comverge, and EnergyConnect (a Johnson Controls company), FERC settled the issue once and for all (with Commissioner Moeller dissenting) that electric consumers who operate customer-owned generation behind the meter can sell demand response into day-ahead energy markets run by RTOs, and can receive the full locational marginal energy price (the LMP) as compensation, as guaranteed by FERC Order 745. <i>(Dkt. EL13-74, Nov. 22, 2013, 145 FERC ¶61,162.)</i></p>
<p>EPSA (the Electric Power Supply Association) and others have long opposed the idea, complaining that customers ought not have their cake and eat it too – that a customer who self-generates behind the meter isn’t really going without.</p>
<p>Rather, that customer is simply going off the grid – taking power maybe from the back yard, and perhaps firing up a high-polluting diesel unit in the process, meaning that a BTM-backed DR resources is just about the un-cleanest resource in the RTO dispatch stack.</p>
<p>This argument – that full LMP for DR invites dirtier resources into the mix – has appeared in pleadings filed D.C. Circuit, where EPSA’s appeal of FERC Order 745 was yet pending at press time. <i>(See, EPSA v. FERC, DC Cir Case Nos. 11-1486, filed Dec. 23, 2011, oral argument held Sep. 23, 2013.)</i></p>
<p>FERC’s rationale in defense is simple. The commission says that the exact manner in which a customer is able to produce a load reduction from the assumed baseline level doesn’t matter. The reduction can come through shifting production, consuming less electricity, or even from internal (BTM) generation – the last of which is not really a negawatt at all.</p>
<p>In other words, in energy markets, DR resources are fungible. A kilowatt-hour of generation is every bit as good as negawatt, and vice versa.</p>
<p>But let’s consider the issue in the context of capacity markets.</p>
<h4>Phantom Virtual Capacity</h4>
<p>Lately PJM has become concerned about the problem of DR “replacement” bids for commitments to its regional capacity market, the RPM (Reliability Pricing Model). The fear is that DR suppliers are speculating, submitting over-ambitious bids in the three-year-forward base residual auction, but then attempting to buy out their positions in future incremental auctions as the time for delivery draws closer, either cashing out or perhaps attempting to substitute a replacement resource for the original DR bid.</p>
<p>And PJM isn’t simply saying that X amount of demand resources is too much. Rather, it’s increases above previously established demand response levels that “are so great that they should be viewed with caution … to ensure that increases above prior levels have … specific identified physical support.” <i>(PJM, Reply Comments, pp. 3-4, FERC Dkt. ER13-2108, filed Dec. 11, 2013.)</i></p>
<p>Andrew Ott, PJM’s senior v.p. of markets, described the problem in a statement filed at FERC in November, following a technical conference held at FERC in October to hash out differences over a new tariff filed by PJM in August to change the way DR resources must bid into the RPM:</p>
<p>“With clearing prices frequently lower in the incremental auctions than … in the base residual auction for the same delivery year, some market participants evidently perceive a seemingly cost-free opportunity to take a position in the BRA that they hope to buy out at lower cost in the incremental auctions.”</p>
<p>And Ott isn’t complaining in the abstract about too much DR swamping the capacity market: “PJM’s reliability concern is not with zones with ‘high DR penetration’ … rather, with zones that have DR offers far above levels cleared in previous auctions in those zones.” <i>(Statement of Andrew Ott, pp. 1,15, FERC Dkt. ER13-2108-000, filed Nov. 8, 2013.)</i></p>
<p>PJM’s independent market monitor Joseph Bowring has complained of the same thing, pointing out that sellers of demand resources in RPM auctions tend to replace those commitments disproportionately compared to sellers of other resource types:</p>
<p>“These replacement transactions may have covered non-physical offers that the seller hoped to cover with a future physical procurement. In other cases, these replacement transactions may have covered non-physical offers based on speculation about relative prices in the BRA and IAs, and there never was a <i>bona fide</i> plan to make them physical. It is difficult to distinguish the motives if the seller is not a purely financial entity, but persistent high levels of replacement capacity purchases by sellers of DR is consistent with a role for both explanations.” <i>(Answer of IMM, p. 2, FERC Dkt. ER13-2108-000, filed Sep. 13, 2013.)</i></p>
<p>As Bowring continues, “RPM was designed to procure a physical capacity product. This requires an offer of a specific physical resource including a specific location.”</p>
<p>In other words, as PJM says, “capacity is not a fungible commodity.”</p>
<p>To address this problem, PJM proposed a new tariff back in August to change the way suppliers of DR resources must submit bids into the regional capacity market.</p>
<p>Under this proposal, demand response bidders in the capacity market must fill out a new “template” for what it calls a DR Sell Offer Plan. As proposed by PJM, DR bidders in capacity markets would be required to provide, among other things: (1) the DR provider’s name, contact information, and intended offer, identified by MWs, DR value, zone and sub-zone; (2) all end-use customer sites expected to participate as of the delivery year; and (3) key assumptions underlying the planned offer, including types of customers targeted and methods of achieving load reductions at certain customer sites. <i>(FERC Dkt. ER13-2108, filed Aug. 2, 2013.)</i></p>
<p>These new requirements have drawn a fierce protest from Comverge, a curtailment services provider in PJM. For one thing, Comverge targets PJM’s proposed requirement that DR providers must submit an officer certification verifying the DR provider’s intent to deliver the same promised demand resources that it bids into the BRA. Comverge protests further that PJM is requiring corporate officers to predict the future.</p>
<p>Frank Lacey, v.p. for regulatory and market strategy for Comverge, explains in comments filed with FERC:</p>
<p>“None of the current certifications required an attestation to expectations about future events or forward-looking statements.</p>
<p>“In stark contrast, the proposed tariff revision requires that the officer attest to an expectation that a DR provider will physically deliver all of the stated megawatts three years in the future.” <i>(Comverge, Post-Conference Comments, pp. 10-11, FERC Dkt. ER13-2108, Dec. 3, 2013.)</i></p>
<p>Lacey argues that the true problem stems from a “broken” capacity market:</p>
<p>“PJM’s real concern is that capacity markets are not producing correct clearing prices.”</p>
<p>PJM defends its proposal to offset the risk that multiple DR offers might be relying on load reductions from the same end users. P3, the PJM Power Producers, agrees, noting that PJM’s reliance on DR to meet reliability targets has grown as DR has displaced existing generation in the supply stack:</p>
<p>“If resources are allowed to bid speculatively in BRAs,” say the power producers, “without demonstrating some reasonable likelihood that they will be physically deliverable, resource adequacy may be jeopardized.” <i>(P3, Post-Conference Comments, p. 4, Dkt. ER13-2108, Dec. 3, 2013.)</i></p>
<p>But note how this vision differs from the bid-based, system-constrained regional energy markets run by RTOs. In both the day-ahead and real-time bidding, neither generation nor capacity are considered to be purely physical. Virtual bidding is permitted. Traders with a day-ahead position can adjust risk with a counterbalancing real-time bid, or chose later to cash out or cover their positions, like a short seller in the stock market. Transmission becomes a financial right, with traders “buying through the congestion” to overcome the grid’s physical limitations by paying a location-based generation price where necessary in order to secure a resource at a location where delivery would be impossible to guarantee under a regime of physical rights.</p>
<p>Why shouldn’t DR bidders also be allowed to settle their capacity commitments financially, in the same manner as in energy markets?</p>
<p>For this question Comverge and Lacey have a ready answer:</p>
<p>“The purpose of the RPM,” it argues, “is to ensure sufficient physical capacity to meet load-serving obligations in the delivery year.</p>
<p>“Any entity offering capacity resources into an RPM auction should do so with the expectation that it will meet its obligations with physical capacity, whether from generating resources, conservation, or DR resources. The market should be indifferent as to the type of physical resource that provides this capacity.” <i>(Frank Lacey, Comverge, Post-Conference Comments, p. 12, FERC Dkt. ER13-2108, filed Dec. 3, 2013.)</i></p>
<p>For demand response aggregators like Comverge, the business is all about probabilities – about reasonable expectations of future customer behavior.</p>
<p>Perhaps it’s worth noting that two years ago, in this column, we reported on how the noted DR advocate Donald Sipe, an attorney representing EnerNOC at that time, had urged FERC to take a more dynamic view for DR bid into regional capacity markets.</p>
<p>Sipe had argued that capacity markets ought to reward customers for a guaranteed load drop (GLD), whether individually or across an aggregated portfolio of customers and resources, even if greater than the customer’s (or the group’s) baseline – past contribution to system peak load, known in PJM as PLC, which ordinarily falls during the summer. <i>(See, “<a href="http://www.fortnightly.com/fortnightly/2011/10/yes-we-have-no-negawatts">Yes, We Have No Negawatts</a>,” Fortnightly, Oct. 2011.)</i></p>
<p>FERC rejected Sipe’s arguments, however, holding that the essence of demand resources isn’t absolute size, nor the scope of its dynamic reduction in load. Rather, a negawatt has capacity value only if it diverts from the expected baseline – only if it frees the grid from having to serve the level of load that the system has already committed to serve, as evidenced by the manner in which it’s been funded and built. <i>(Dkt. ER11-3322, Nov. 4, 2011, 137 FERC ¶61,108.)</i></p>
<p>And so the biggest concern for Comverge, as it has expressed in comments filed with FERC, “is that there is no clarity around the definition of reasonable expectation, and no parameters around what would justify a change of expectation.”</p>
<p>As Comverge sees it, the only documentation that would appear to satisfy the new proposed tariff “is an actual contract with a customer for the delivery year.”</p>
<p>The company fears that PJM’s new tariff aims to “walk back DR participation in the face of clamor from stakeholders … because it delivers capacity to PJM too cheaply, too reasonably, and too efficiently for their liking.”</p>
</div></div></div><div class="field field-name-field-article-category field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Category (Actual): </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/article-categories/states">The States</a></li><li class="taxonomy-term-reference-1"><a href="/article-categories/ferc">FERC</a></li><li class="taxonomy-term-reference-2"><a href="/article-categories/transmission">Transmission</a></li></ul></div><div class="field field-name-field-members-only field-type-list-boolean field-label-above"><div class="field-label">Viewable to All?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-article-featured field-type-list-boolean field-label-above"><div class="field-label">Is Featured?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-department field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Department: </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/department/commission-watch">Commission Watch</a></li></ul></div><div class="field field-name-field-image-picture field-type-image field-label-above"><div class="field-label">Image Picture:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/1401-CW.jpg" width="800" height="562" alt="" /></div></div></div><div class="field field-name-field-fortnightly-40 field-type-list-boolean field-label-above"><div class="field-label">Is Fortnightly 40?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-law-lawyers field-type-list-boolean field-label-above"><div class="field-label">Is Law &amp; Lawyers:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-tags field-type-taxonomy-term-reference field-label-above clearfix">
<div class="field-label">Tags:&nbsp;</div>
<div class="field-items">
<a href="/tags/mississippi">Mississippi</a><span class="pur_comma">, </span><a href="/tags/itc">ITC</a><span class="pur_comma">, </span><a href="/tags/entergy">Entergy</a><span class="pur_comma">, </span><a href="/tags/linda-blair">Linda Blair</a><span class="pur_comma">, </span><a href="/tags/thumb-loop">Thumb Loop</a><span class="pur_comma">, </span><a href="/tags/federal-energy-regulatory-commission">Federal Energy Regulatory Commission</a><span class="pur_comma">, </span><a href="/tags/ferc">FERC</a><span class="pur_comma">, </span><a href="/tags/transco">Transco</a><span class="pur_comma">, </span><a href="/tags/gridflorida">GridFlorida</a><span class="pur_comma">, </span><a href="/tags/emi">EMI</a><span class="pur_comma">, </span><a href="/tags/vertical-integration">Vertical integration</a><span class="pur_comma">, </span><a href="/tags/miso">MISO</a><span class="pur_comma">, </span><a href="/tags/missouri">Missouri</a><span class="pur_comma">, </span><a href="/tags/arkansas">Arkansas</a><span class="pur_comma">, </span><a href="/tags/eai">EAI</a><span class="pur_comma">, </span><a href="/tags/negawatt">negawatt</a><span class="pur_comma">, </span><a href="/tags/new-york-iso">New York ISO</a><span class="pur_comma">, </span><a href="/tags/enernoc">EnerNOC</a><span class="pur_comma">, </span><a href="/tags/viridity">Viridity</a><span class="pur_comma">, </span><a href="/tags/comverge">Comverge</a><span class="pur_comma">, </span><a href="/tags/energyconnect">EnergyConnect</a><span class="pur_comma">, </span><a href="/tags/johnson">Johnson</a><span class="pur_comma">, </span><a href="/tags/moller">Moller</a><span class="pur_comma">, </span><a href="/tags/epsa">EPSA</a><span class="pur_comma">, </span><a href="/tags/btm">BTM</a><span class="pur_comma">, </span><a href="/tags/pjm">PJM</a><span class="pur_comma">, </span><a href="/tags/rpm">RPM</a><span class="pur_comma">, </span><a href="/tags/reliability-pricing-model">Reliability Pricing Model</a><span class="pur_comma">, </span><a href="/tags/andrew-ott">Andrew Ott</a><span class="pur_comma">, </span><a href="/tags/joseph-bowring">Joseph Bowring</a><span class="pur_comma">, </span><a href="/tags/frank-lacey">Frank Lacey</a> </div>
</div>
Sat, 28 Dec 2013 00:45:47 +0000meacott16969 at http://www.fortnightly.com